1. Field of the Invention
The present invention pertains to processing gravity and magnetic data using vector and tensor data along with seismic data and more particularly to the inversion of gravity and magnetic data and combining with seismic data to detect abnormally pressured formations in general, and with specific application to areas underneath anomalies such as salt, igneous or magmatic formations.
2. Related Prior Art
Typically, while drilling an oil or gas well, the density of the drilling mud must be controlled so that its hydrostatic pressure is not less than the pore fluid pressure in any formation along the uncased borehole. Otherwise, formation fluid may flow into the wellbore, and cause a xe2x80x9ckick.xe2x80x9d Kicks can lead to blowouts if the flow is not stopped before the formation fluid reaches the top of the well. If the fluid contains hydrocarbons, there is a serious risk of an explosion triggered by a spark. For this reason, wellbores are drilled with a slight excess of the borehole fluid pressure over the formation fluid pressure.
A large excess of the borehole fluid pressure over the formation fluid pressure, on the other hand, is also undesirable. Fractures in the borehole wall may result in loss of circulation of the drilling fluid, resulting in stuck drill strings. Even if drilling can be continued, it is slowed down, resulting in greater costs. Serious formation damage may also occur.
Pressure prediction is done by estimating certain key parameters that include the overburden stress or confining stress, which is defined as the total lithostatic load on a rock volume at a given depth, and the effective stress, which is defined as the net load on the grain framework of the rock at a given depth. These two relations are then used in the Terzaghi effective stress law to estimate the fluid or pore pressure. Terzaghi""s law states that:
Pc=Pe+Pp
where:
(Pc)=the confining stress
(Pe)=the stresses born by the grains, and
(Pp)=the stress born by the fluid.
Some workers treat a special case of Terzaghi""s law where the confining stress is assumed to be the mean stress as opposed to the vertical confining stress. It should be acknowledged that this difference exists, but that it does not effect the embodiments of the present invention as they will pertain to estimating the total overburden load, which can then be converted to either vertical confining stress or mean stress based on the stress state assumptions that are made. The current prior art used for estimating confining stress is to use a density log from a nearby calibration well and integrate the density data to obtain the overburden load. This calibration was then applied from the mudline down to depths usually beyond the depth of sampling to predict the overburden away from the calibration well.
It has long been recognized that velocities of seismic waves through sedimentary formations are a function of xe2x80x9ceffective stress,xe2x80x9d defined as the difference between the stress caused by the overburden and the pore fluid pressure. A number of methods have been used to measure the seismic velocities through underground formations and make an estimate of the formation fluid pressure from the measured velocities. Plumley (1980) and U.S. Pat. No. 5,200,929 issued to Bowers, (the ""929 patent) describe a method for estimating the pore fluid pressure at a specified location. The method also accounts for possible hysterisis effects due to unloading of the rock formation. The method utilized a pair of sonic velocity-effective stress relations. One relationship is for formations in which the current effective stress is the highest ever experienced. A second relationship is used when the effective stress has been reduced from the maximum effective stress experienced by the rock and hysteresis must be accounted for.
The ""929 patent uses density data from nearby wells or from a geologically similar well to obtain the overburden stress. In most circumstances, the overburden stress may be adequately described by general compaction models in which the density increases with depth, giving rise to a corresponding relation for the relation between depth and overburden. In the absence of well control, determination of the overburden stress even within a sedimentary column is problematic. Furthermore, there are circumstances in which the model of a density that increases uniformly with depth is not valid. In such cases, the assumption of increasing density with depth is violated and a different approach to estimation of the overburden stress is needed.
There are several types of situations that may arise wherein a model of density increasing with depth and compaction is not valid. In the first case, there is a region of abnormally high density in the subsurface, usually of magmatic origin. The region could consist of an extrusive or intrusive volcanic material having relative density of 2.8 or higher. When such a formation is present within a sedimentary section where the relative density is typically between 2.4 and 2.65, the result is an increase in the overburden stress underneath the formation over what would be determined by prior art calculations. On the other hand, a region of abnormally low density may occur from salt bodies (2.10) or shale diapirs. In such a case, the overburden stress is abnormally low compared to what would be determined by prior art methods. In either case, even if the effective stress could be determined from seismic velocity measurements, a formation fluid pressure determination based on a prior art density model would be invalid.
In prior art, it is common to extrapolate away from a control well to derive an initial pressure model. When abnormally pressured sediments are present having higher porosity and lower density than sediments in the control well, the model of increasing density with depth is violated and the confining pressure is overestimated.
Exploration for hydrocarbons in subsurface environments containing highly anomalous density variations have always presented problems for traditional seismic imaging techniques by concealing geologic structures beneath zones of anomalous density.
There have also been methods for identifying subsurface formations beneath highly anomalous zones using only seismic data to create a model and processing the data to identify formations in light of the model. By further processing acoustic seismic data, the original model is modified or adjusted to more closely approximate reality.
An example of further processing seismic data to improve a model is U.S. Pat. No. 4,964,103, titled xe2x80x9cThree Dimensional Before Stack Depth Migration of Two Dimensional or Three Dimensional Dataxe2x80x9d, issued to Johnson. This patent provides a method of creating a three dimensional model from two dimensional seismic data. This is done by providing a method of ray tracing to move before stack trace segments to their approximate three dimensional position. The trace segments are scaled to depth, binned, stacked and compared to the seismic model. The model can then be changed to match the depth trace segments which will be stacked better, moved closer to their correct three dimensional position and will compare better to the model. This patent uses a rather extensive seismic process to modify a seismic model that is not accurate.
There is a need for a method for accurate determination of fluid pressures in the subsurface that (1) does not require the availability of density logs and (2) can more accurately determine the density of the subsurface in 2D or 3D away from and deeper than the limits of density from well control. Such a method should preferably be able to obtain fluid pressure even in the presence of anomalous formations that have densities significantly different from those expected in normal sedimentary columns or that predicted by density values in single or multiple wells. The present invention satisfies this need.
The present invention incorporates a robust inversion process to determine subsurface fluid pressures using seismic data in combination with vector and tensor potential fields data, both gravity and magnetics. Velocity estimates from seismic data are used to provide an initial estimate for the density of subsurface formations using relations such as the well known Gardner relation calibrated to local well data. This is used in an inversion scheme to invert the potential fields data and obtain a density model for the subsurface. In the inversion process, constraints may be placed on the density model based on the seismically determined velocities. The seismically determined velocities give an estimate of the effective stress while the inverted density model gives the overburden stress. The difference between the overburden and the effective stress is the fluid pressure. In an alternate embodiment of the invention, the method is used to obtain density models of anomalous zones such as salt bodies, shale diapirs, and extrusive or intrusive igneous bodies, where seismic data is unable to obtain accurate velocity estimates or do accurate imaging due to ray path distortions. The geometries and densities of these anomalous bodies are then used to generate improved overburden estimates compared to the prior art where only nearby well densities were used to constrain the overburden. For example, in the case of salt formations in the Gulf of Mexico, a top of a salt map derived from seismic imaging along with a density model and bathymetry, are utilized to produce a base of salt model from the inversion process. This may be used as input to the seismic data to obtain velocity (and effective stress) information underneath the anomalous zone.